The first major repowering project in the UK, the upgrading of Scottish Hydro-Electric's 1550 MWe Peterhead power station to gas turbine combined cycle operation, not only provides a baseload plant with peaking capacity and raises thermal efficiency from 38 to 55 per cent, it reduces NOx emissions by 85 per cent and secures competitive performance well into the next millennium. Even more remarkable is the outstanding operational flexibility obtained by making strategic use of the already largely amortized existing equipment. The project cost of $380 million covers the cost of a North Sea gas pipeline and a new grid connection.
This is one of the UK’s largest energy efficiency projects and it strengthens Hydro-Electric’s position as the UK’s most efficient generator,” according to Scottish Hydro-Electric’s Director of Generation, Dr James Martin, “The repowering of Peterhead will secure our competitive position in the electricity market.”
The combined cycle repowering of the existing 1550 MWe of generating plant will result in many more MW per dollar of investment than the $450 million worth of investment would have brought from a new power plant of similar efficiency a green field site. The use of the existing steam system represents a major saving in capital expenditure. It will also bring inestimable advantages in terms of operating availability, fuel arbitraging opportunities and energy trading benefits.
The investment in this project has been made on the balance sheet of Hydro-Electric on top of another $1200 million of planned investment already committed to the company’s business strategy of growth by acquiring tangible assets, but this programme is being jeopardized by the UK government’s apparently open-ended embargo on gas fired power plant. If the moratorium continues, Hydro-Electric will have to consider looking abroad or returning value to their investors, most likely in the form of a share buy-back.
The plant could have been rescheduled to a mid-merit, lower utilization role, but the more entrepreneurial option of investing the substantial sums needed to raise the plant’s fuel conversion efficiency to strengthen its competitive position was preferred as promising the better economic rewards.
Peterhead is not affected by the gas fired plant moratorium but the company’s new combined cycle unit Keadby 2, which has Section 36 consent, is subject to discussions with the DTI over its merits to continue developments. Hydro-Electric believes that the existing contracts for Seabank 2 will allow it to proceed.
The existing plant
First commissioned in 1980, the existing plant, which consists of two 660 MWe conventional boilers and steam turbine generating sets supplied by Mitsui Babcock and Alstom Energy, plus two simple cycle 115 MW Frame 9E gas turbine sets supplied by John Brown Engineering Ltd, was designed to operate on a wide range of fuels:
Heavy fuel oil
Natural gas liquids
Since 1990, the plant has been running on cheap, sour, oil-associated gas from the Miller Field, which is now largely depleted.
In February 1998, Siemens KWU was selected from the six competing bidders for the $290 million (DM 520 million) contract to convert one of the two existing 660 MWe units to a combined cycle system. They will supply three V94.3A gas turbine generator sets with associated three pressure level plus reheat, natural circulation exhaust heat recovery boilers.
The contract requires that during the two years of repowering work, power generation in the steam plant system will continue unhindered with the exception of a nine week outage for upgrading critical items of steam plant. The repowered plant is due to commence full commercial operation in the summer of 2000 to add nominally 1200 MWe of high efficiency plant to Hydro-Electric’s generating capacity.
To understand how the project developed we need to go back over the past history of the Peterhead power station.
The original plant
First commissioned in 1980, the two 660 MWe units of the Peterhead power station were built on a coastal site at Boddam on the Aberdeenshire coast. The site was chosen for its proximity to the North Sea oil fields, a port capable of unloading large oil tankers, availability of cooling water, excellent foundation conditions, but also anticipating the availability of a suitable fuel gas from the nearby on-shore reception facilities at St Fergus some 18 km away.
The plant initially ran on heavy fuel oil with on site storage capacity of 180 000t. When the plant was designed in the mid 1970’s, the full impact of the Middle East oil crises was not yet apparent.
The St Fergus opportunity became a reality in 1982, and a direct pipeline to the power station was installed. Agreements were finalized with Shell Expro and Esso, and from 1982 to 1984, the station burnt natural gas liquids – a mixture of ethane, propane and butane was stripped from the gas that was fed ashore from a number of North sea oil platforms via undersea pipelines. Methane in the gas was sold to British Gas, and the heavier condensates were piped to the Peterhead for flaring in the power plant boilers prior to being fed to the Mossmoran ethylene processing plant.
Gas flows were variable according to off-shore production, British Gas nominations, and gas composition, but the HFO burning capability, which allowed fuel to be switched on load at any time and mixed in any ratio in either boiler, allowed full output to be maintained even at times of low gas supply.
In 1984, with the commissioning of the ethylene plant at Mossmoran, the supply of fuel gas was suspended, but the pipeline, reception facility and control room have been retained for continuous gas burning during Mossmoran outages.
The British government removed its restriction on the use of gas as a power generation fuel in the mid 1980’s. In 1988, Hydro-Electric contracted with the Miller Field partners – BP, Conoco, Enterprise and Sante Fe – to take the entire oil-associated gas production from the Miller oil field some 240 km north-east of St Fergus. This was sour gas containing substantial carbon dioxide and some hydrogen sulphide in the mixture which would have required costly removal before it could deployed in the British Gas system, but it could be used in the power station boilers with very little pretreatment required. Miller Field sour gas has been the main fuel used by Peterhead since 1992.
The gas is supplied on a “must take” basis, and is fed to St Fergus via an undersea line at 175 bar, and from there via an underground line to the power station at 35 bar. However, the field is now close to exhaustion. The sub-sea and land pipeline have a carrying capacity that is in excess of the Miller production, and sub-sea tees were installed to cater for supplies from other sources, and the Shell reception facilities are still available.
Coincident with the start of the Miller gas supply, the second phase of Peterhead Power Station development – two 115 MWe open cycle Frame 9E gas turbine generator units were commissioned, as much as anything to ensure that generating capacity would still be available during outage of either 660 MWe unit to burn the full commitment of “must take” gas.
What, then, was the logic for further upgrading? With about 65 per cent of the assumed residual life remaining, privatization of the electricity supply industry had led to increased competition in the market place. This precipitated the choice – become becoming competitive or to close. The repowering option promised the obvious benefits:
Natural gas was the competitive fuel
Combined cycle plant generate at higher efficiencies
Repowering enabled asset value to be realized by offering competitive levels of thermal efficiency
The next phase
With the phasing out of the Miller gas, the new generating plant will be supplied from the company’s portfolio of gas contracts, offering scope to exploit Hydro-Electric’s prowess in fuel and electricity trading, and the scope for arbitrage in particular.
With the addition of the gas turbine combined cycle phase, the existing steam cycle is also being substantially upgraded and adapted to follow a unique concept which provides exceptional flexibility through a range of operating modes.
The underslung direct sea-water cooled condensers supplied by GEC Delas was retubed with titanium tubes two years ago. Now, virtually all of the innards have been replaced, and it is possible to handle a complete steam dump from the combined cycle WHRB’s as well as from the conventional boilers. The HP feed heaters have been replaced, air heaters have been upgraded, and a new digital governor system has been installed.
It supports five alternative operating modes:
Simple Brayton cycle
Rankine cycle: The existing natural circulation Babcock & Wilcox multi-fuel boilers, which are in good condition, are retained in the system and still be used in conjunction with the original GEC four cylinder impulse-reaction turbines to produce full output in the original mode with full load following capabilities with a station efficiency of 39.72 per cent gross generated. The 36 dual firing burners in each boiler can burn gaseous or liquid fuels in any ratio, but this mode is only likely to used when HFO prices are more favorable than natural gas.
Brayton cycle: All three gas turbines can be operated independently in open cycle to produce over 795 MWe.
Combined cycle: The maximum efficiency of 55 per cent is gained when using the three V94.3A gas turbines with their three pressure level plus reheat WHRB’s feeding steam to the unit 1 steam turbine. This will give some 1150 MWe of output, of which only 350 to 360 MWe will come from the 660 MWe rated steam turbine, but the steam turbines have the potential to be further enhanced and achieve increase combined cycle thermal efficiency.
Hybrid mode: In this mode, the combined cycle output is augmented by supplying further steam from the fired boiler to the steam turbine to add another 300 MWe, making the total output 1420 to 1450 MWe. Steam turbine output is still restricted by last stage flow limitations.
Mixed mode: With unit 1 running on the full combined cycle output of 1150 MWe, unit 2 running in Rankine cycle mode to give its full output of 660 MWe, the fired boiler being brought into use to supply additional steam to the unit 1 steam turbine, and the two open cycle gas turbines adding another 230 MWe, the potential maximum output could be as high as 2300 MWe. However, the current transmission constraints limit output to the present maximum of 1550 MWe.
The water/steam cycle system
The condensate from the condenser is shared between the exhaust heat recovery boilers and fired boiler in accordance with the ratio of steam produced by the respective boilers, as is the cold reheat steam flow.
The main change arising from the adoption of a triple pressure with reheat exhaust heat recovery boiler is the increase in mass flow through the steam turbine due to augmentation from the IP and LP steam generation. This increases the relative LP cylinder blade loading while the HP is reduced due to adjustment in the cylinder pressure ratios.
The re-powered set will operate over a sliding pressure range of 60 to 130 bar with a design efficiency in combined mode and hybrid mode of 55+ per cent and 52 per cent.
Reductions in harmful emissions claimed for the repowered plant, amount to an 85 per cent reduction in NOx, a 90 per cent reduction in SO2, and a 50 per cent reduction in CO2. Some of this is due to the higher efficiencies in the various operating modes.
Visual impact will be little changed, with the lower profile new plant sited on the existing excavation on the seaward side of the site.
With a capital cost of only 60 per cent of that for an equivalent combined cycle system on a green field site, utilization of existing station services, HRSG pressure up to 140 bar, integration of steam/feed piping and controls, and the new variable speed boiler feed pump system, the repowered Peterhead power plant should be well able to generate a commercial return on investment in a competitive market as a load following base load generating plant or as a peaking power plant at commercially attractive efficiency.
TablesTable 1. Repowered output and efficiency Table 2. Repowered plant operating parameters Table 3. Expected emissions reduction